NewBase 632 special 23 june 2015

Copyright © 2015 NewBase www.hawkenergy.net Edited by Khaled Al Awadi – Energy Consultant All rights reserved. No part of this publication may be reproduced, redistributed,
or otherwise copied without the written permission of the authors. This includes internal distribution. All reasonable endeavours have been used to ensure the accuracy of the information contained in this
publication. However, no warranty is given to the accuracy of its content. Page 1
NewBase 23 June 2015 - Issue No. 632 Senior Editor Eng. Khaled Al Awadi
NewBase For discussion or further details on the news below you may contact us on +971504822502, Dubai, UAE
Oman: Phoenix Power makes MSM debut
Oman observer
Phoenix Power Company was traded for the first time on Muscat Securities Market yesterday, and
according to analysts performed on the expected lines. The shares surged by 33.36 per cent to
close at 150 baisas. The shares touched a high of 155 baisas and a low of 145 baisas during the
course of days transaction.
Joice Mathew, senior manager, United Securities, said, “Over 128 million shares were traded on
the debut, generating about RO19.3 and amounting to 97 per cent of the total shares traded on
the day. He added that the company is expected to perform on similar lines in the next few days
and it may be noted that only 128 million shares of the 332.7 million allocated to retail investors
were traded yesterday.
He said there was a big demand from institutional buyers and pension funds, which had received
2.5 per cent allotment. The share was oversubscribed to the tune of 18 times, generating RO1
billion from investors against an issue size of RO 56.3 million.
The company has allotted a minimum of 3,000 shares and 8.57 per cent of additional shares
applied by retail investors. Phoenix Power is the largest power plant in Oman, with an installed

capacity of 2,000 MW. The contracted power capacity represents 27.8 per cent of Oman’s MIS
total currently contracted capacity of approximately 7,197 MW based on OPWP’s seven-year
statement (2014-2020).
Close to 97 per cent of the total revenues of Phoenix Power in FY 2015 (excluding fuel revenue,
which is virtually a pass-through) will be through capacity charges from OPWP for the contracted
power capacity of the plant.
These capacity charges are payable regardless of orders or output of the Plant. Phoenix Power’s
capacity charges are calculated so that they cover its debt service and other fixed costs, such as
operating and maintenance, insurance, taxes and capital returns.
The project benefits from the proven contractual framework adopted by the Government, and
leverages the strong track record of the country in tendering of IPPs and IWPPs. The output from
Phoenix Power’s installed capacity is contracted with OPWP, through a single long-term PPA
which expires on March 31, 2029.
Beyond the PPA period, Phoenix Power shall either extend its PPA with OPWP or sell its output
in a liberalized market in a power pool or to eligible customers. Its decision to do so will depend,
amongst other factors, on the evolution of the market regulations set by the Authority for Electricity
Regulation, Oman (AER).
About Phoenix Power
Vision
Phoenix Power draws its business strategy following our vision statement, as below:
“To become a respected brand within the Oman’s power market by being the safest, most reliable,
efficient, and environmentally conscious power provider, ensuring exceptional services and value
to our offtaker, shareholders and other stakeholders.”
History
The ambitious journey of Phoenix Power started in 2011, with Oman Power and Water
Procurement Company (OPWP) inviting proposals for the development of an Independent Power
Project (IPP) at Sur. Following the competitive bidding process run by OPWP in 2011, the
shareholders were awarded the contract to build the plant, which saw the incorporation of Phoenix
Power Company.
The plant has been established under a Build, Own, Operate (BOO) scheme, which enables it to
be operated beyond the Power Purchase Agreement (PPA) term of 15 years, either by extending
the PPA (if agreed by OPWP), or by selling the power into an electricity pool which may exist at
that time.
Shareholders
Axia Power Holdings B.V.
Chubu Electric Power Sur B.V.
Qatar Electricity & Water Company
Multitech LLC

Kuwait: Construction costs to delay s al-Zour oil refinery
Reuters + NewBase
The start-up of Kuwait’s al-Zour crude oil refinery is expected to be delayed after rising
construction costs forced state refiner Kuwait National Petroleum Co (KNPC) to seek more
money to finance the plant, a KNPC spokesman said on Monday.
Officials had previously said start-up would occur by late 2018 or early 2019 and pegged the
cost of the facility at 4 billion dinars ($13.3 billion). But KNPC spokesman told Reuters by
telephone: “We are seeking additional funds to start awarding (contracts). We are already two
months behind and we don’t know when we will get the funds.”
KNPC said in a statement that a request for the new government money would be submitted
to the Supreme Petroleum Council, a top oil policy body.
The company did not say when the request might be approved or how much extra money
KNPC needed, but Kuwaiti daily al-Seyassah quoted the company’s chief executive
Mohammed Ghazi al-Mutairi as saying the amount was estimated at 800 million dinars.
The 615,000 barrel per day oil refinery, originally planned more than a decade ago, would
be the biggest in the Middle East, but the project has been repeatedly delayed by
bureaucratic and political issues, including tensions between Kuwait’s parliament and the
cabinet.
KNPC said it
had asked
companies
which had bid
for work on
the project to
extend the
validity dates
of their bids
until it
obtained the
new funds.
Bids for one
of the
contracts,
related to the
tank farm, did
not meet
specifications
so the
company is
inviting fresh
bids and set
July 7 as the
date for them
to be submitted. The refinery will make diesel, kerosene and naphtha for export and low-
sulphur fuel oil for domestic power stations.

Saudi Aramco may shut Jeddah refinery in several years
By Reuters + NewBase
State oil giant Saudi Aramco is considering whether to close its 90,000 barrel per day crude oil
refinery in Jeddah after several years because of age and environmental concerns, industry
sources said.
The refinery, which started operating in 1967, serves much of the country’s western region and its
closure would increase demand at other Saudi facilities. It produces liquefied petroleum gas,
gasoline, diesel, asphalt and jet fuel, and exports naphtha.
Aramco was originally considering whether to close it in 2018 but now looks likely to postpone the
closure to as late as 2022 because of growing domestic demand for oil products and since
construction of a new refinery at Jizan, also on the Red Sea coast, has been delayed, said one
source.
Another said Jeddah’s growth had left the refinery in the middle of the city, which created
environmental issues that contributed to a likely decision to close it. The sources declined to be
named because they were not authorised to talk to media. In response to questions by Reuters,
Aramco said on Sunday that it had no information to release at this time.
Aramco has said it plans to bring the Jizan refinery online by 2018. However, industry sources
said this was now expected to be delayed by at least two years for several reasons, including
technical problems with building infrastructure in the sea.

A Singapore-based trader said Saudi Arabia’s new Jubail and Yanbu refineries, operated by
Aramco, France’s Total and China’s Sinopec, would likely supply gasoline output lost by the
eventual closure of the Jeddah facility.
He said the impact on the international naphtha market would not be big as the refinery exported
only about 40,000 tonnes per month. The United Arab Emirates’ Ruwais refinery is to raise yearly
naphtha exports to over 10 million tonnes from the current 7.5 million tonnes, traders have said.
IMPACT ON LUBEREF
The Jeddah refinery is next to, and supplies feedstock and power to, a base oil refinery run by
Luberef, a joint venture between Aramco and Jadwa Industrial Investment Group. Luberef makes
a total of around 550,000 tonnes per year of oil lubricants from its two refineries at Jeddah and
Yanbu.
Luberef said it was now considering whether to shut the Jeddah facility eventually and expand
Yanbu. “This is now in the planning phase and Luberef will be ready if Aramco’s Jeddah refinery
closes, Luberef said in an emailed statement.
One source familiar with the matter said the Luberef shutdown could happen in 2020. Companies
based in Saudi Arabia have received a request from Luberef to express their interest for front-end
engineering and design work, industry sources said.
“They want to build a new vacuum distillation unit with a capacity of 26,000 bpd — they want to
move some parts from the old plant,” said one. Luberef is already expanding its Yanbu plant by
doubling capacity to produce a new, high-quality base oil.
The company originally said it planned to start commercial production of this oil in the fourth
quarter of 2015, but its statement to Reuters last week indicated the date would be later.
“Production of the G-II expansion will commence by the second quarter of 2016 of which high
quality G-II base oil will be introduced in (the) local and export market,” it said.

Norway: Tullow's Zumba exploration well in PL 591 in the
Norwegian Sea disappoints… Source: Tullow Oil
Tullow Oil has announced that theZumba exploration well (6507/11-11) in licence
area PL 591 in the Norwegian Sea has not encountered hydrocarbons and will
now be plugged and abandoned.
The primary objective of the well was to prove hydrocarbons in the Upper Jurassic
Rogn Formation with a secondary target in the Mid-Jurassic Garn Formation of the
Fangst Group. The well found no reservoir development in the Rogn Formation and,
while the Garn Formation had good reservoir quality, no hydrocarbons were present
in either target.
The well was drilled by the Leiv Eiriksson rig in 270 metres of water to a Total Depth
of 2875 metres. Tullow Oil Norge is the operator of PL 591 with 40%
equity. Lime Petroleum Norway (25%), Rocksource(20%*) and North
Energy (15%) hold non-operated interests.

Madagascar: Madagascar Oil operations - updates
Source: Madagascar Oil
Madagascar Oil has announced the appointment of Jefferies International as a strategic
advisor to the Company and that a new, updated, company presentation is available on the
Company's website.
Updated Company Presentation:
The Company's CEO, Robert Estill, will be presenting at the Oil & Gas Council Africa Assembly
in Paris on 23 June 2015 and a copy of the presentation to be made at that Assembly is now
available on the Company's website. The Company Presentation includes the following items
which are additional to the information previously reported by the Company and are therefore
summarised below. The new information is based on the latest Company estimates and is
consistent with the Company's plans as outlined in the approved Block 3104 Tsimiroro
Development Plan (the 'TDP').
Tsimiroro Development Plan:
• Drilling costs for each development well are now estimated at US$150,000 per well based
on latest data. It is expected that well completion, flowlines, tie-back and artificial lift costs
will add a further US$140,000 cost for each development well. Both well cost components
represent a reduction over existing TDP submission costings due to recent market price
conditions.
• A new production profile up until 2045 has been highlighted which shows the latest
estimated production growth forecasts under three newly defined stages as follows:
o Anchor Stage: the initial growth stage which shows gross production achieving
between 7,000-10,000 barrels of oil per day ("bopd") from approximately 400
development wells in the period up to the end of 2018/early 2019. It is estimated
that funds of between US$200-US$400 million will be required to fund this stage
from a mix of equity, oil sales, farm-in, financial agreements with service companies
or through other funding options. Jefferies will assist Madagascar Oil in determining
the optimal funding route for this stage, including the identification and securing of a
strategic partner(s), as referred to above. This stage was previously referred to by
the Company as "Phase 1" of the TDP.

o Fast Track Stage: a further growth stage which envisages gross production
reaching 50,000 bopd by 2021/2022. This stage would involve, amongst other
things, the construction of a pipeline to the west coast of Madagascar and new
coastal offtake facilities, increased drilling activities through a larger rig count and an
additional central processing facility.
The latest Company estimates indicate that additional funds of between US$400-
US$600 million will be required for this stage and it is envisaged that funding options
may be available from a variety of avenues including debt, infrastructure funds,
crude oil offtakers, equity, cashflows arising from crude oil sales and from other
sources. The Company has already commenced discussions with third parties
interested in funding elements of this stage and it is envisaged that discussions will
continue as the Anchor Stage progresses. The Fast-Track Stage was previously
referred to by the Company as "Phase 2" of the TDP.
o Enhanced Stage: this stage envisages gross production growing from 50,000 to
over -100,000 bopd through 2025 with the rate of growth being dependent on many
factors, in particular the number of drilling rigs in operation at any one time and pace
of development. Latest Company estimates indicate that this stage will be fully
funded from project cashflows with no additional external funding being required.
Tsimiroro Development Value:
• The Company has run a range of commercial cases for the Tsimiroro Development based
around varying oil prices, production profiles, oil recovery rates, capital spend and other
cost assumptions. The Company's latest base case estimate (NPV10 value) is US$2.6
billion for the full contingent resource development, which is based on:
o the production profile arising from the three stages, referred to above;
o a late May 2015 forward oil curve price deck (US$62.50 per barrel rising to US$80
per barrel in 2018 onwards);
o capital and opex costs as included in the TDP; and
o estimated recovery factor of around 40% of the 1.7 billion barrels of contingent
resources.
• The Company Presentation shows a range of sensitivities around the base case of
US$2.6 billion using different oil price assumptions (ranging from US$40 per barrel to
US$100 per barrel) and different stock tank oil initially in place ("STOOIP") volumes
(ranging from 0.6 billion barrels STOOIP to 3.5 billion barrels STOOIP). The impact is
shown on a chart in the Company Presentation (page 11).
• The latest NPV10 values are the Company's best estimate at this time and will inevitably
change over time as new information emerges for the development.
Click here for Madagascar Oil Company Presentation June 2015

Netherlands: Output at Groningen gas field to be capped at 30 bcm
Source: Reuters via Yahoo! Finance
Dutch Economy Minister Henk Kamp will propose a further tightening of production at Groningen,
Europe's largest gas field, the Dutch news agency ANP reported on Monday, sending European
gas prices higher. Output at the gas field, the world's 10th largest, will be capped at 13.5 billion
cubic metres (bcm) in the second half of this year and at 30 billion bcm for the whole of 2015, ANP
said.
In February Kamp had ordered
production to be cut to an
annualised rate of 33 bcm for
the first half of the year, from
39.4 bcm previously, after the
Safety Board said gas
companies, regulators and the
government had all failed to take
the threat of earthquakes
seriously enough.
The report of a production cut
of 3 bcm in the second half of
2015 led to a tightening of
liquidity on the Title Transfer
Facility (TTF) gas hub and sent
prices in Europe higher. A
government spokeswoman
declined comment on the
figures. A formal decision was
expected on Friday. A
spokesman for the NAM
Shell/Exxon Mobile joint
venture, which exploits the
Groningen field, was
unavailable for comment.
Speculative buying by banks and traders drove gas prices higher on Monday, despite weak
underlying fundamentals in regional gas markets, which are heavily oversupplied.
'There are no numbers to click on the TTF,' one trader said, referring to a trading platform that
enables buying or selling of gas at the Dutch gas trading hub. It seems like every trader is
waiting, nobody wants to offer, they are waiting to see which way the market will move.'
Dutch gas prices at the TTF hub were higher in early afternoon trade. The July contract was up
1.48 percent at 20.60 euros per megawatt hour, while the September contract gained 1.63
percent, also to 20.60 euros/MWh. The NBP Winter 2015 contract rose 1.9 percent to 48.65
pence per therm while the 3Q 15 contract climbed 2.7 percent to 43.50 pence per therm.
The ANP report, citing anonymous sources in The Hague, said the latest decision was based on
a projection that temperatures will remain mild this year and that demand can be met by tapping
3 bcm in overcapacity at the Norg storage facility in Drenthe. In a conflicting report, local
television channel RTV Noord said Kamp would propose a production cap of 33 bcm.

US:crude oil production growth helps reduce Gulf Coast imports
Source: U.S. Energy Information Administration, Petroleum Supply Monthly
In recent years, higher domestic production of light, tight crude oil has led to a reduction in crude
oil imports. Certain types of crude oil have been affected more than others; for example, the
increased economic availability of domestic light, tight crude oil has virtually eliminated Gulf Coast
imports of light crude oil. In the past year, Gulf Coast imports of medium crude oil have also fallen
because of increased production from the Eagle Ford, Bakken, and Permian regions.
One of the key characteristics of crude oil is its density, measured by API gravity as established
by the American Petroleum Institute. Less-dense liquids have higher API gravities. Crude oils with
API gravities of 35 or above are considered light; 27 to 34 are medium; less than 27 are heavy.
From the first quarter of 2014 to the first quarter of 2015, medium-grade crude oil imports to Gulf
Coast refineries decreased 45%, from 1.5 million barrels per day (b/d) to 0.8 million b/d. On the
other hand, over that same period there was a 0.4 million b/d (22%) increase in imports to Gulf
Coast refineries of heavy crude oil. Improved refining margins from processing additional volumes
of heavy crude have resulted in a 3% increase in gross atmospheric distillation unit (ADU)
throughput in the Gulf Coast region over this period, from 8.0 million b/d to 8.2 million b/d.
Almost all medium-grade crude oil imports are from Middle Eastern countries. Gulf Coast imports
of medium crude oil from
Saudi Arabia decreased
by 52% from the first
quarter of 2014 to the
first quarter of 2015, from
0.9 million b/d to 0.4
million b/d. Similarly, Gulf
Coast imports of medium
crude oil from Kuwait
decreased by 46% over
this period, from 0.4
million b/d to 0.2MBD.

US industrial natural gas usage falls unexpectedly
Reuters
US manufacturers have not soaked up as much excess shale gas in the first half of 2015 as
expected, but the shortfall may be an anomaly as a Gulf Coast manufacturing boom is poised to
insulate the sector from seasonal demand fluctuations.
Average industrial demand for gas in 2015 was expected to increase nearly 4% over 2014,
according to federal energy forecasts. But almost halfway through the year, it has eased about 1%
to 21.7bn cubic feet per day from 22 bcfd a year earlier, according to Thomson Reuters Analytics.
The primary reason for the decline was a milder winter this year than last year’s brutal cold in the
heavily industrialised US Midwest and Gulf Coast. “The industrial sector has become more
temperature-sensitive over the years, so it’s not surprising industrial demand was a little
disappointing this winter,” said Kyle Cooper, managing director of research at energy consultancy
IAF Advisors in Houston.
Experts, however, expect the industrial sector to become less weather-sensitive as more
manufacturing facilities enter service along the Gulf Coast, where heating is in less demand than
in the Midwest.

Power generators and manufacturing companies will consume most of the gas in the US over the
next 25 years, according to the US Energy Information Administration. So far this year, however,
only the power sector had gobbled up its share of near-record output from shale fields.
Power generators accounted for 33% of US gas consumption, burning on average 23.9 bcfd so far
in 2015. That compared with 20.1 bcfd a year earlier and a 10-year average of 19.0 bcfd.
With the retirement of dozens of US coal plants for economic and environmental reasons, power
generators used near-record amounts of gas this year because the fuel was relatively cheap.
Futures at the Henry Hub benchmark supply point in Louisiana averaged $2.77 per million British
thermal units so far this year, the lowest since 2012. That compared with $4.66 per mmBtu for the
same time in 2014.
And the market expects prices to remain low for years as shale gas output grows, with futures
trading below $4 through 2022. Plentiful and affordable gas supplies from shale plays have
transformed the US from one of the world’s highest-cost producers 10 years ago to among the
lowest-cost today.
Chemical companies alone expect to spend more than $100bn to build or expand more than 200
US projects and create more than 300,000 jobs by 2023, according to the American Chemistry
Council lobbying group.
“The boom in industrial demand will not take off until 2017 to 2020, when many new
manufacturing facilities, especially chemical plants, enter service,” said Gregory Shuttlesworth,
executive director of natural gas at consultancy PIRA Energy Group in New York.
Experts said they did not expect manufacturers to dominate the US gas market the way they once
did, however. “The industrial sector will soon get back to the same volume of gas it used in 2000,”
IAF Advisors’ Cooper said, “but I doubt we’ll ever see manufacturing back to the same percentage
of total gas used 15 years ago.”
The EIA forecast
gas used by
industrial
companies would
rise to about 22.5
bcfd in 2016, the
first time it would
top the 22.3 bcfd
level set in 2000.
In the mid 2000s,
many gas-
intensive US
companies fled
for lower cost
markets after gas
futures jumped
above $10 per mmBtu in 2000 and then to an all-time high past $15 in 2005 after Hurricanes
Katrina and Rita devastated the Gulf Coast. The EIA said it expected US industrial companies to
continue to consume about 30% of the nation’s gas over the next 25 years, compared with more
than 35% 15 years ago.

Oil Price Drop Special Coverage
Oil prices fall on oversupply concerns, weak economic data
REUTERS + NEWBASE
Oil prices fell on Tuesday on worries over a global glut, while surveys showing a contraction in
manufacturing activity in China and Japan also dragged on market sentiment. An expected
drawdown in U.S. crude stocks, however, put a floor under prices.
Brent crude was down 20 cents at $63.14 a barrel as of 0355 GMT (1155 EDT), after closing the
previous session up 32 cents. U.S. crude for August delivery fell 34 cents to $60.04 a barrel. The
July contract, which expired on Monday, closed up 7 cents at $59.68 a barrel.
"I think the Japan and China PMI figures are weighing on the market," said Jonathan Barratt, chief
investment officer at Sydney's Ayers Alliance. China and Japan are Asia's two biggest oil
importers.
The HSBC/Markit Flash China Manufacturing Purchasing Managers' Index (PMI) edged up to 49.6
in June, a three-month high, from 49.2 in May, but remained below the 50 mark, which separates
contraction from expansion. Japanese manufacturing activity contracted slightly in June with the
Markit/JMMA flash Japan Manufacturing PMI falling to a seasonally adjusted 49.9 in June from a
final 50.9 in May.
"Although China’s figures picked up slightly, we continue to believe that growth remains weak as
PMI figures are not moving past 50. We expect no change to crude demand from Japan and
China in the near future with manufacturing PMI figures being weak," Phillip Futures said.
Growth in U.S. gasoline stocks, which increased by almost 500,000 barrels in the week to June
12, high U.S. crude output of about 9.6 million barrels per day and 2 million barrels per day of
excess capacity by oil producers cartel OPEC added to oversupply concerns, Barratt said.
But analysts expect U.S. commercial crude oil stocks to have dropped by an average of 1.8 million
barrels to around 466 million barrels last week.

Saudi & UAE keep growing despite cheap oil
SG/Agencies + NewBase
Saudi Arabia and the UAE continue to witness growth despite lower oil prices, a report by Crédit
Agricole Private Banking said Monday, noting that the UAE even recorded high levels of job
creation during May, while Saudi Arabia’s output and new orders expanded.
Commenting on the financial
institution’s research report
“Macro Comment – Mena
Update”, Dr Paul
Wetterwald, chief economist
at Crédit Agricole Private
Banking, said “interestingly
in the UAE, once again new
orders and new export
orders components reflected
strong growth, while job
creation hit a three-month
high. This is reflected in the
UAE’s non-oil private sector PMI which did not decline significantly in May (56.4) compared to
56.8 in April. On the other hand, input costs rose contrasting with a slight decline of the output
prices charged by companies.”
Dr Wetterwald added “in this background, it is too early to infer from this latest change that a
downward trend in the CPI indices has started. We can see that the UAE’s CPI was +4.2 percent
year-on-year in April, which is the same as in Dubai where inflation can be an issue. Nevertheless,
we can say that the UAE is yet to fully feel the pinch of the lower oil price across its relatively
diversified economy in comparison to GCC peers.”
“Similarly in Saudi Arabia, output and new orders expanded but the rate of growth and pace of job
creation eased somewhat during the month. It was interesting to note that the Kingdom’s headline
PMI last month (57.0) was at its lowest level since May 2014. While the most recent data in the
PMI series still depicts a growing non-oil private sector economy, our estimate of growth in Saudi
Arabia is more conservative,” he said.
“For example, based inter alia on the latest Saudi Arabia Monetary Authority statistics, we get a
Q1 2015 nominal GDP growth estimate which is only slightly positive.” Dr Wetterwald noted that
with regards to food inflation, the recent softening of world food prices should bring significant
benefits to GCC consumers.
“This is indicated by the FAO food price index in May 2015, which was down 20.7 percent year-
over-year and 1.4 percent month-on-month. Given the large weightage on food items in
consumers’ baskets, this lower food price scenario will be positive for consumers in the GCC
countries where most of the food requirements are imported from other places,” he said.
“This situation will prevail provided no strong El Niño episode occurs. El Niño is a natural
phenomenon which is a key factor worldwide for the agricultural sector, as it contributes to
extreme weather. A strong El Niño would put the crops of some agricultural commodities at risk,
leading to higher food prices during and after its occurrence,” Dr Wetterwald added.

NewBase For discussion or further details on the news below you may contact us on +971504822502, Dubai, UAE
Your partner in Energy Services
NewBase energy news is produced daily (Sunday to Thursday) and
sponsored by Hawk Energy Service – Dubai, UAE.
For additional free subscription emails please contact Hawk Energy
Khaled Malallah Al Awadi,
Energy Consultant
MS & BS Mechanical Engineering (HON), USA
Emarat member since 1990
ASME member since 1995
Hawk Energy member 2010
Mobile: +97150-4822502
khdmohd@hawkenergy.net
khdmohd@hotmail.com
Khaled Al Awadi is a UAE National with a total of 25 years of experience in
the Oil & Gas sector. Currently working as Technical Affairs Specialist for
Emirates General Petroleum Corp. “Emarat“ with external voluntary Energy
consultation for the GCC area via Hawk Energy Service as a UAE
operations base , Most of the experience were spent as the Gas Operations
Manager in Emarat , responsible for Emarat Gas Pipeline Network Facility &
gas compressor stations . Through the years, he has developed great
experiences in the designing & constructing of gas pipelines, gas metering &
regulating stations and in the engineering of supply routes. Many years were spent drafting, &
compiling gas transportation, operation & maintenance agreements along with many MOUs for the
local authorities. He has become a reference for many of the Oil & Gas Conferences held in the
UAE and Energy program broadcasted internationally, via GCC leading satellite Channels.
NewBase : For discussion or further details on the news above you may contact us on +971504822502 , Dubai , UAE
NewBase 23 June 2015 K. Al Awadi

NewBase 632 special 23 june 2015

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